Embodiments of the present invention relate to the management of wellbore fluids utilizing in drilling and workover operations for wells constructed for recovery of natural resources, which may include wells for producing oil, gas, geothermal resources, water, and other minerals. The typical application for this invention will be in wells in which high temperatures and/or pressures are encountered in the drilling or workover operation. However, embodiments of the present invention may also be utilized in applications where the properties of the circulating fluid are impacted by lower temperatures and/or pressures, or scenarios in which both extremely cool and hot temperatures are encountered. For example, a hydrocarbon well which is drilled from an offshore drilling vessel in very deep water may encounter very cool temperatures in the marine riser, but may encounter extremely hot temperatures as the well penetrates deep strata. Likewise, wells drilled in Artic locations may have extremely cold temperatures in strata near the surface, but may encounter very hot temperatures in deeper strata as the drilling operation proceeds.
Different types of fluids circulated are circulated in wellbores for a variety of purposes. Among other purposes, fluids are circulated to: (1) maintain a pressure balance with formation pressures which may be encountered in the wellbore; (2) cool a drilling assembly; (3) remove drill cuttings and other materials from the wellbore; (4) transmit hydraulic energy to the bit and drilling assembly; (5) suspend cuttings when drilling operations are paused; (6) seal permeable formations to prevent damage to producing reservoirs; (7) limit corrosion in downhole tubulars; and (8) facilitate cementing and completion operations. The fluids circulated in the wellbore include drilling muds of all kinds, completion fluids (such as packer fluids, perforating fluids, and corrosion inhibitors), stimulation fluids (such as acid, solvents, and frac fluids), foaming agents, and other known fluids circulated within wellbores in the petroleum and natural resources industries. Embodiments of the present invention may be used with these fluids, or combinations thereof. The term “circulating wellbore fluid” as used in this disclosure and within the following claims shall be understood to be referring to these and other known fluids which are circulated within a wellbore.
Many of the fluids utilized for circulation in the wellbore are non-Newtonian fluids, where the fluid viscosity is dependent on pressure, temperature, and the velocity at which the fluid flows through the hydraulic system. The hydraulic system for these applications, and used for embodiments of the present invention, is formed by the wellbore (which may have a cased hole portion and an open-hole portion, and, in offshore operations, a marine riser extending through the body of water), a drill string or working string inside the wellbore (which may be formed by drill pipe or tubing and may include a bottom hole assembly comprising a bit, drill collars, stabilizers, logging tools, mud motors, directional drilling components, and other components), surface tanks for holding and cleaning the fluids, surface processing equipment for cleaning, cooling, mixing, and testing the fluid, and interconnecting piping having valves, meters, etc., for hydraulically connecting all of the various components.
In typical hydrocarbon well drilling operations, drilling fluids are circulated down through the drill pipe down to the drilling assembly, and flowing up in the annulus defined between the drill string and the inside wall of the wellbore, bringing back to the surface the cutting debris generated by the drill bit. In addition, the returning drilling fluids bring back the entrained heat generated by cutting. The increasing frequency of drilling into deeper—and thus hotter—strata has required the cooling of the drilling fluids. Chilling and cooling systems have been developed for cooling the wellbore fluids, such as that described in U.S. Pat. No. 4,215,753. In this system, the drilling fluids are circulated through heat exchangers at the surface and returned to the wellbore. However, in deeper wells, there is significant heat transfer as the cooled or chilled fluids are pumped down the wellbore. Insulated drill pipe is frequently employed in combination with a surface cooler or chiller to address these situations.
The impacts of temperature on the circulating wellbore fluid can be significant. The rheological properties of drilling fluids are frequently approximated to be independent of pressure and temperature. This may be a satisfactory approximation in shallow wells where the temperature changes are not large, because the rheological variations with the temperature change are small. However, in those situations where the temperature changes are large, or in situations where there is a small margin between pore pressure and fracture pressure thereby requiring precise hydraulic calculations to achieve well control, the effects of temperature and pressure on wellbore hydraulics need to be known so that affirmative steps may be taken to manage the temperature and pressure of the fluids circulating within the wellbore. For purposes of this disclosure and claims, the phrase “managing properties of a circulating wellbore fluid” shall mean adjusting controllable parameters of the circulating wellbore fluid to achieve temperatures and pressures which: (1) are within the capacity of the surface and subsurface equipment; (2) do not unintentionally exceed the fracture gradient of the reservoir; (3) maintain control of wellbore pressures; (4) minimize reservoir damage; (5) eliminate or minimize hazardous conditions for personnel; and (6) increase operational efficiency and decrease operational expense. The controllable parameters, each of which may be largely dependent upon the others, shall be understood to mean: (1) the temperature of the circulating wellbore fluid; (2) the chemical composition and pH of the circulating wellbore fluid; (3) the pump pressure applied to the circulating wellbore fluid; (4) the volumetric flow rate of the circulating wellbore fluid; (5) the density of the circulating wellbore fluid; (6) the viscosity of the circulating wellbore fluid; (7) the heat capacity of the circulating wellbore fluid; (8) the yield point of the circulating wellbore fluid; (9) the solids content of the circulating wellbore fluid; (10) the rate of penetration; (11) the directional program; (12) the casing program; (13) the cementing program; (14) the configuration of the drilling string, including any insulation which is utilized in the drill string; and (15) the configuration of the bottom hole assembly.
The management of the temperature and pressure of the circulating fluids provides a number of advantages, including obtaining greater precision in well control, optimizing drilling rates, protecting equipment and personnel, and reducing overall operational costs.
Temperature affects the rheology of the circulating fluids, so the behavior and interactions of the water, clay, polymers and solids in a mud or circulating fluid are impacted according to changes in temperature. In general, a drilling mud gets thinner with increases in temperature. However, the specific impact is influenced by the type and total solids in the drilling mud. Clays can be dispersed by higher temperatures, which can result in increased flocculation and severe thickening. Laboratory testing and practical experience have shown that temperature can have a substantial effect on the flow characteristics of non-Newtonian fluids like drilling muds. Temperatures of the circulating fluids raise various issues concerning degradation of the fluid and on the performance and efficiency of the overall hydraulic system. For example, some ingredients of drilling fluids are particularly impacted by elevated temperatures, such as the hydrolysis of starches, depolymerization of certain organic thinners, or irreversible chemical reactions (such as that of clay and lime). These impacts can affect the filtration, viscosity and shear strength of the drilling fluid which, if not attended, can have significant consequences on well control, drilling cost, formation protection, and other factors.
Laboratory testing and field experience have demonstrated how the impact of temperature on the rheological properties of a wellbore circulating fluid is influenced by the composition of the fluid. For example, it has been shown that thinning will occur in a mud with 25 ppb of bentonite, 350 ppb of barite and 9 ppb of lignosulfonate until a temperature of 220 degrees F. is reached. However further increases in temperature, to 320 degrees F., result in a significant increase in viscosity. If the concentration of lignosulfonate is increased to 15 ppb, the higher viscosity at 320 degrees F. is prevented. It has also been found in laboratory testing that gel strength of a fluid can be significantly impacted by bentonite content, pH, and temperature.
Because of the impact of the fluid system on well control, safety, reservoir protection, drilling efficiency, and related factors, and the influence of circulating fluid temperature on other fluid properties, there is a distinct advantage in being able to manage the circulating fluid temperature on a near real-time basis. However, this goal is complicated by a number of factors including the initial composition of the circulating fluid, the work imparted to the fluid, the heat transfer taking place throughout the hydraulic system, and the changing composition of the circulating fluids as wellbore materials, such as cuttings, are circulated from the wellbore by the circulating fluid. As fluids are circulated through the hydraulic system described above, the temperatures of the fluid may vary according to the real time location of the fluid within the hydraulic system. Liquids expand when heat is applied and are compressed by pressure. Therefore, the density of the fluid decreases with increasing temperature, but increases with increasing pressure. As a drilling fluid is pumped downhole, its density is changed by the temperature and pressure effects. Thus the effective management of the temperature and pressure of a circulating wellbore fluid, while presenting a number of advantages, is a complicated problem for which a solution is offered by embodiments of the present invention.